Well Barrier

ABSTRACT

A well barrier is for sealing off a first portion of a wellbore from a second portion of the wellbore, the first portion having a higher fluid pressure than the second portion. The well barrier is held in place in the wellbore by a holding means. The well barrier is preshaped to disintegrate in at least three barrier elements upon activation of a disintegration means, at least one of the barrier elements having a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore. A method is for controlling a disintegration of the well barrier.

This invention relates to a barrier. More particularly it relates to a well barrier and/or zone isolation devices for sealing off a first portion of a wellbore from a second portion of the wellbore in wells related to the production of hydrocarbons.

In conjunction with the completion of wells, involving steps such as the installation of production casing, production liner (lower completion) and production tubing (upper completion), barrier systems are commonly used.

In one scenario, a barrier is mounted in top of the lower completion (production liner), to isolate the reservoir whilst installing the production tubing (upper completion) in the upper section of the well.

In another scenario, a barrier is installed in the bottom of the production tubing during the installation of this. Once the tubing is positioned correctly, pressure is applied on the inside to set the production packer. To form a sealed enclosure during such operation, to allow for pressurizing the internals of the tubing, the bottom of the tubing has to be sealed off. Most commonly, such seal is provided for by using a barrier device.

A common requirement to the above described barrier systems is the ability to withhold the required pressure during the stages where such barrier functionality is required. A second, equally important requirement is that the barrier can be opened or removed when barrier functionality is no longer required, to open the liner and/or production tubular so that fluids can flow through it.

Traditionally, these temporary completion barriers were installed and retrieved using well service techniques such as wireline or coil tubing.

In many offshore fields, very costly drilling rigs are utilized for the purpose of drilling and completing a well. In such cases, any time spent on wireline or coil tubing operations will contribute to making the completion of the well increasingly expensive, as it increases the time the drilling rig has to be rented for the completion of the well. To eliminate the need to operate the above mentioned barrier systems on wireline or coil tubing, barriers that can be operated to open without the need for physical intervention into the well have been developed. Initial systems of such kind were ball valves, flapper valves, sliding sleeves or similar that was operated open by cycling well pressure using a pump at the surface of the well.

Cycling pressure means repeated pressurizing and depressurizing (bleeding down) the tubing (and/or liner top) pressure in order to operate mechanical counter systems associated with the downhole barrier. Typically, after a certain amount of pressure cycles, the mechanical counter system will engage with a barrier activation mechanism that causes the barrier/valve to open. Typically, such engagement is achieved by the counter mechanism ultimately operating a valve member of the activation system, that allows well pressure to work against an atmospheric chamber via a piston, and the resulting work is used to shift the valve member to an open position. In other versions, such engagement is achieved by the counter mechanism ultimately operating a mechanical lock of the activation system that releases a pre-tensioned spring mechanism in the activation mechanism, whereupon this causes the valve member to shift to an open position. Other similar methods of activating and shifting the valve member may be applied. Such methods would be appreciated by a person skilled in the art, and are not described further herein.

A drawback with barriers made of metal, such as the barrier systems described in the previous section, is that if the cycle open mechanism or activation mechanism fails to operate, or if the valve element fails to shift open for any other reason, alternatives for mechanical removal of the barrier are associated with a relatively high cost and risk. An example of alternative removal is to use coil tubing to shift open, or in the worst case mill out a ball valve or a steel flapper valve.

Typical causes of failure may be debris in the well that jams the cycle open mechanism, the activation mechanism or the valve element itself.

Other related barrier systems are made of non-metallic materials such as for example glass, ceramics, salt or other more brittle materials. A common method for barrier removal in this respect is a mechanical cycle open mechanism that triggers an activation mechanism where an explosive charge is detonated inside or in close proximity to the brittle barrier. An alternative method entails the mechanical cycle open mechanism to operate a mechanical lock that holds a pre-tensioned spring system. When releasing the pre-tensioned spring, this will drive an impact device such as a spear into the brittle barrier to crush it.

A great benefit with using brittle, non-metallic barrier elements is that they are easier to remove mechanically than steel barriers should the mechanical cycle open method of activation fail for any reason. Rather than having to use coil tubing to mill out a steel barrier, wireline could be used, together with a spear, hammer device or other device or combination of devices to crush the barrier. Thus, a quicker, more cost effective backup activation is possible.

Publication US 2003000710 A1 discloses a downhole non-metallic sealing element system related to downhole tools such as bridge plugs, frac-plugs, and packers having a non-metallic sealing element system for isolation of formation or leaks within a wellbore casing or multiple production zones.

Publication US 2009283279 A1 discloses a zonal isolation system for use in a well. The zonal isolation system includes a zonal isolation tool, at least one anchor, and at least one polished bore receptacle. The zonal isolation system includes a setting string for activation of the zonal isolation tool and/or the at least one anchor. It may also include an isolation string for maintaining separation zones during production or injection of the well.

Publication US 2002195739 A1 discloses to a method of manufacturing a sealing or an anti-extrusion component for use in a downhole tool. The component is formed from a composition that contains a polyetherketoneketone or a derivative of a polyetherketoneketone.

Publication US 2009151958 A1 discloses a method and device for temporary well zone isolation. In particular, it discloses temporary well zone isolation devices with frangible barrier elements and methods for the disintegration of frangible barrier elements.

Publication GB 2391566 A discloses a formation isolation valve for use in a subterranean well. A mechanical apparatus may be used to open and close the valve. The actuators may include a rupture disc or other forms of remotely operable actuator.

U.S. Pat. No. 6,167,963 B1 discloses a drillable composite packer or bridge plug including substantially all nonmetallic components.

U.S. Pat. No. 6,796,376 B2 discloses a composite bridge plug system for containing a well bore with reduced drill up time.

A generic problem with barriers made of brittle materials is that impact or a large force is required to crush them. In the case where explosives are used, this may entail a potential safety risk. Requirements to create mechanical impact and/or a large force in an activation system make it somewhat more complex and susceptible to failure. The presence of debris/impurities in the well may impair the performance to the extent where the opening/removal activation fails.

Still another method for removing a barrier made of a brittle material is to disintegrate the barrier by means of fluid pressure. WO 2009126049 discloses a plug element for conducting tests of a well, a pipe or the like, comprising one or more plug bodies of disintegratable/crushable material set up to be ruptured by internally applied effects. The plug comprises an internal hollow space set up to fluid communicate with an external pressure providing body, and the plug is designed to be blown apart by the supply of a fluid to the internal hollow space so that the pressure in the hollow space exceeds an external pressure to a level at which the plug is blown apart.

However, brittle material barriers that are crushed by the means mentioned above, may give rise to another problem. In some cases, despite crackling the brittle barrier, the specific well situation (local pressure, fluids, compacted debris surrounding the barrier) may prevent the particles from physically being removed to any significant distance from their original position. As a result, the crackled (but not physically disintegrated) barrier may still represent a relatively solid body in the well, preventing flow, hence obstructing for subsequent operational steps. Ultimately, such crackled barriers may have to be physically removed by wireline or coil tubing interventions as described above.

The object of the invention is to remedy or reduce at least one of the drawbacks of prior art.

The object is achieved in accordance with the invention, by the characteristics stated in the description below and in the following claims.

According to a first aspect of the present invention there is provided a well barrier for sealing off a first portion of a wellbore from a second portion of the wellbore, the first portion having a higher fluid pressure than the second portion, wherein the well barrier is held in place in the wellbore by a holding means preventing movement of the well barrier in a direction from the first portion to the second portion, the well barrier comprising:

-   -   multiple barrier elements initially held together by a         connection means to form the barrier, the barrier having a         surface area facing the first portion of the wellbore that is         larger than the surface area facing the second portion of the         wellbore;     -   a sealing means for preventing fluid flow from the first portion         to the second portion;     -   a destabilizing mechanism arranged for disengaging the         connection means from at least one of the barrier elements upon         activation of the mechanism, so that support between adjoining         barrier elements is removed, thereby disintegrating the well         barrier.

This has the effect that the shape and form of the individual barrier elements after disintegration of the barrier can be controlled so that the likelihood for the barrier elements creating problems after disintegration is minimized. Further, providing a preshape wherein at least one of the barrier elements having a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore may provide a well barrier that is capable of carrying a high fluid pressure in the first portion, but very vulnerable to fluid pressure in the second portion of the wellbore.

In one embodiment of the present invention the multiple barrier elements are formed in one piece provided with notches in at least a portion of the surface of the well barrier, and the connection means comprises the non-notched portion of the well barrier.

In one embodiment of the present invention the barrier elements are provided by means of separate, preshaped barrier elements being connected to each other by the connection means, the connection means being selected from one of or a combination of: an adhesive; a wire; the sealing means, to form the well barrier.

In one embodiment of the present invention the preshape may be provided by means of a combination of one or more portions of the barrier being provided by notches and one or more portions of the barrier being provided by separate, preshaped barrier elements.

The well barrier may further be provided with a support element for supporting the barrier elements. Preferably, the support element faces the second portion of the wellbore.

The sealing means may be a sealing element. Preferably, the sealing element faces the first portion of the wellbore. The sealing element is selected from a material suitable for providing an impermeable barrier between the fluid in the wellbore and the barrier elements. In one embodiment the sealing element is selected from the group comprising an elastomeric membrane, a coating, an adhesive.

In one embodiment the sealing means is the non-notched portion of the well barrier.

Preferably, the well barrier has the form of a pressure arch towards the first portion of the wellbore.

In one embodiment the well barrier is provided with a further well barrier, the further well barrier being mirrored with respect to the well barrier about a plane being perpendicular to a longitudinal axis of the well bore. The second portion of the wellbore is in this embodiment defined between said well barrier and said further well barrier.

In one embodiment of the present invention the destabilizing mechanism comprises a releasable holding means arranged such that upon releasing the holding means the well barrier is moved by the fluid in the first portion, the movement causing the well barrier to disintegrate.

In one embodiment of the present invention when the second portion is defined between the well barrier and the further well barrier, the destabilizing mechanism is an arrangement for raising the pressure of the fluid in the second portion to a level higher than the fluid pressure in the first portion of the wellbore facing the further well barrier

At least one of the multiple barrier elements may have a form as a keystone supporting adjoining barrier elements, the keystone element having a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore. The at least one keystone element may be provided by means of multiple elements.

The barrier facing the first portion of the wellbore may have a concave lens shape, wherein a majority of the barrier elements are wedge shaped with a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore.

In a second aspect of the present invention there is provided a method for controlling a disintegration of a well barrier according to the first aspect of the invention, the method comprising:

-   -   pre-shaping the barrier to disintegrate in multiple barrier         elements of desired size and shape; and     -   activating a destabilizing mechanism that will provide a force         sufficient to break a connection means initially holding the         multiple barrier elements together, thereby causing the barrier         to disintegrate into said multiple barrier elements of desired         size and shape.

The following describes a non-limiting example of a preferred embodiment illustrated in the accompanying drawings, in which:

FIG. 1 a-1 c illustrate one example of generic use of the invention;

FIG. 2-5 c illustrate design, functionality and operation of one barrier according to a preferred embodiment of the invention;

FIG. 6 illustrates combination of barrier elements to provide for two way pressure integrity;

FIG. 7 illustrates an embodiment where multiple barrier elements are used to hold pressure from the same direction, to provide for additional operational safety and redundancy;

FIG. 8 a-8 c illustrate additional system features used to ensure a reliable barrier removal/disintegration process;

FIG. 9-14 illustrate use of pressure compensation systems in conjunction with a double barrier design further to a preferred embodiment. Such pressure compensation systems are used to provide for a lower pressure between the barrier elements than on the outside of the barrier elements, respectively;

FIG. 15 illustrates a preferred design principle for barrier elements constituting the barrier;

FIG. 16 a illustrates an exploded view of a barrier according to the present invention;

FIG. 16 b illustrates the barrier in FIG. 16 a arranged in a portion of a pipe; and

FIG. 16 c illustrates the barrier in FIG. 16 b seen from the first portion of a wellbore.

FIG. 1 a-1 c illustrate a borehole 101. Casing 102 is used to prevent the borehole 101 from collapsing during drilling and subsequent production, and to seal off the borehole wall to prevent unwanted leakage to or from strata/zones in the underground and ultimately to provide a barrier between the pressurized hydrocarbon reservoir and the open environment. In most cases, the casing is cemented to the rock wall as will be appreciated by any person skilled in the art and thus not illustrated herein. A generic well completion is illustrated. In this illustrated case, the lower completion comprises a cemented production liner 103 which is open towards the hydrocarbon reservoir via perforations 104. A person skilled in the art will know that the design and configuration of the production liner 103 may vary significantly from what is illustrated herein. The production liner 103 is anchored to and forms a seal towards the casing 102 by means of a liner hanger system 105.

The upper completion comprises the production tubing 106, which is stung into the lower completion by means of a seal stinger assembly 107. A sealing arrangement 108 comprising a barrier 114 according to the present invention is installed below a production packer 109. In the top of the well, the tubing 106 is terminated in the wellhead 110. The completion design may vary significantly from what is shown in FIG. 1, and there are common completion components that are not illustrated herein, such as a downhole safety valve. These facts will be appreciated by a person skilled in the art. Similarly, the device according to the present invention can be used for other completion designs than what is shown herein, and FIG. 1 provides for an example only.

When running the completion in the hole, the production packer 109 is not activated, as illustrated in FIG. 1 a.

The centerline 115 of the tubular is illustrated for reference.

Now considering FIG. 1 b, a pump 111 is put in fluid communication with the wellhead 110. In order to set the production packer 109, meaning to expand the mechanical anchors and seal elements to engage with the casing 102, the pump 111 is used to apply high pressure to the fluid inside the tubing 106. This is possible due to the sealed enclosure formed by the tubing 106, the sealing arrangement 108, the wellhead 110 and the pump 111. After setting the packer 109, the barrier 114 is no longer required in the well. The next step is to remove the barrier 114 so that the well can be put on production or injection.

To remove the barrier 114, the fluid inside the tubing 106 is pressure-cycled as described earlier in this document, using the pump 111. For each complete pressure cycle, a mechanical counter mechanism 112 is operated one step. After a certain amounts of steps, the mechanical counter mechanism 112 will interact with an activation module 113 that triggers the opening and/or removal of the barrier 114. In summary, after a certain amount of cycles, i.e. pressurizing and de-pressurizing the tubing fluid, the barrier 114 opens. FIG. 1 c illustrates the well completion after the barrier 114 has been removed.

The mechanical counter system 112 and activation system 113 could be replaced or supplemented by alternative activation systems, such as battery operated, sensor based or timer based activation systems, controlled by internal micro controllers or similar available in the marked. Details of such associated activation mechanisms would be appreciated by a person skilled in the art and no further details of such are provided for herein.

FIG. 2 shows in a larger scale one embodiment of the barrier 114 with an associated activation system 113 according to present invention. A counter system 112 as indicated in the FIGS. 1 a-1 c or alternative systems for wireless activation of the barrier system not shown herein. However such a system is assumed included in the well completion, and in fluid communication with the activation system 113 through a flow channel 201.

In a preferred embodiment, upon activation, a mechanical counter system 112 as indicated in FIGS. 1 a-1 c, or alternative system for wireless activation, operates a valve manifold so that a pressurized fluid is lead into the activation system 113 through the flow channel 201. Details of operation of any mechanical counter system 112, or alternative wireless activation system, valve manifolds etc. is known to a person skilled in the art and not further described herein. In the embodiment shown in FIG. 2, the activation system 113 has a tubular form and is incorporated or connected the production tubing 106. Only one side of the cut activation system 113 is illustrated. The center of the cut activation system 113 is illustrated by the dotted line 115.

The barrier 114 shown in FIG. 2 is made up of smaller barrier elements some of which are indicated by reference numerals 114 a, 114 b, 114 k. A relatively thin-walled base dome 114 s made of a brittle material such as concrete is applied to simplify the construction of the barrier 114 and to prevent unwanted premature migration/movement of the barrier elements 114 a, 114 b, 114 k with respect to each other. In one embodiment of the present invention, the barrier elements 114 a, 114 b, 114 k are attached to the base dome 114 s and/or each other by means of an adhesive agent, or using metal wire or other suitable attachment methods. In another embodiment, a relatively thin walled ring (not illustrated herein) made of a similar brittle material is forming the circumference of the barrier 114 to facilitate mounting and provide inter-component stability of the barrier 114.

In an alternative embodiment, the barrier 114 is constituted by one element provided with notches providing nicking of the barrier 114 into barrier elements 114 a, 114 b, 114 k of a desired, predetermined size.

The barrier 114 is locked in place inside the tubular of the activation system 113 by means of a finger coupling 207 and a lock/cover sleeve 208.

Upon activation, pressurized fluid is routed from a valve manifold operated as described elsewhere in the document and into the activation system 113 via channel 201. Here, the pressurized fluid acts on piston 202. The piston 202 is mechanically in contact with holding profile 204 via piston mandrel 203. Longitudinal slots 205 are provided in the piston mandrel 203. A set of engagement bolts 209 are screwed into the lock/cover sleeve 208, the engagement bolts 209 protruding through the slots 205 of the piston mandrel 203.

In one embodiment, the smaller elements 14 a, 14 b, 114 k are free to move with respect to each other, but form a mechanically stable geometry when mounted as shown in FIG. 2. In alternative embodiments, a thin walled dome 14 s assists in holding the geometry of the barrier 114 stable. In the described embodiment, the barrier 114 is designed to hold forces from a direction illustrated by arrow 210.

Thus, there is provided a well sealing arrangement 108 where the force integrity is provided by at least one barrier 114 associated with at least one activation system 113 that includes at least one operable support element 207, wherein said barrier 114 is construed by smaller barrier elements 114 a, 114 b, 114 k that form a stable mechanical structure against forces from at least one side of the sealing arrangement 108; and said stable mechanical structure becomes unstable by means of operating at least one support element 207.

Thus there is provided well sealing arrangement 108 where the force integrity is provided by at least one barrier 114 associated with at least one activation system 113, wherein said barrier 114 is construed by smaller barrier elements 114 a, 114 b, 114 k that form a stable mechanical structure against forces from at least one side of the sealing element 108, said stable mechanical structure becomes unstable by means of operating the activation system 113.

To ensure pressure integrity and not only force integrity, the barrier 114 is in the embodiment shown provided with an elastomeric membrane 212. In other embodiments, the elastomeric membrane 212 could be replaced with other coating agents suitable for forming a seal. Such a coating agent may be adhesives, resin coating or similar.

Now consider FIG. 3. When the high pressurized fluid pushes the piston 202 downwards, the holding profile 204 is shifted simultaneously. After a certain travel, the holding profile 204 will no longer radially support the finger coupling 207. When the radial support is removed from the finger coupling 207, the fingers will be pushed radially outward and away from the centerline 115 of the tubing 106. In the embodiment shown in FIG. 4, the finger coupling 207 is formed so that the fingers bias towards a position that is radially outward into a recess 503 from the resting position when the barrier 114 is assembled. In another embodiment, the push created by the pressure force indicated by arrow 210 acting on barrier 114 forces the fingers of the finger coupling 207 radially outward into the recess 503.

Now consider FIG. 5 a. As a consequence of the finger coupling 207 no longer supporting the barrier 114, the barrier 114 is free to move downwards. As piston 202, piston mandrel 203 and support element 204 is shifted downwards; some distance after the radial support is removed from the finger coupling 207, the piston mandrel 203 engages with the engagement bolt 209 when the bolt 209 abuts an end portion of the slot 205. As a consequence, the hold/cover sleeve 208 is shifted downwards. At the time when the engagement bolt 209 and associated profile in the hold/cover sleeve 208 lands on a shoulder 501 provided in a tubing recess 502, the downward movement of piston 202, piston mandrel 203 and support element 204 stops. At this point in time the lock/cover mandrel 208 covers the opening between the bore and the recess 503. Preferably, a mechanical lock system will ensure that the lock/cover mandrel is locked in place with respect to recess 503. Such a lock system is not shown, but may for example be a snap lock or other suitable locking device that will be appreciated by a person skilled in the art.

Still considering FIG. 5 a, the barrier 114 is now free to move further downwards in the tubing 106. In a preferred embodiment of the invention, the barrier 114 will now disintegrate due to forces caused by pressure according to arrow 210, associated flow forces, collisions with the wall of the tubing 106, or collision with other objects in the well. In a preferred embodiment, the smaller barrier elements 114 a, 114 b, 114 k are free to move with respect to each other, or engaged to each other by means of relatively weak adhesive, thin metal wires, or other means that will disengage when relatively modest forces are acting on the barrier 114. In the case a relatively thin walled dome 114 s is used, alternatively in combination with a thin walled rim in the circumference of the barrier 114, a preferred embodiment of this is that the thin walled dome 114 s and/or rim is made in a brittle material that will crush in the process subsequent to the radial disengagement of finger coupling 207. FIG. 5 b illustrates the situation where the barrier 114 is in the process of disintegrating.

As would be appreciated by a person skilled in the art, a barrier element of the kind illustrated herein as barrier 114 is designed to withstand a larger forces from the direction illustrated by arrow 210 than in the opposite direction (from below in the embodiment illustrated.

FIG. 5 c illustrates another preferred feature. Here, the elastomeric membrane 212 is physically bonded to the cover mandrel 208 along its circumference 504. By means, when activating the barrier 114, the barrier elements 114 a, 114 b, 114 k etc will be physically separated from the elastomeric membrane 212. Moreover, the elastomeric membrane 212 will ultimately be inverted and torn/permanently destructed from the fluid forces acting on it. This way, one avoids a potential problem of the mechanical parts such as barrier elements 114 a, 114 b, 114 c and sealing parts such as the elastomeric membrane 212 of the barrier 114 being able to re-form a barrier seal elsewhere in the well. The bonding between elastomeric membrane 212 and cover mandrel 208 could be achieved by means of mechanical fixture means, adhesives, or by vulcanizing the elastomeric membrane 212 to cover mandrel 208.

FIG. 6 illustrates a barrier system comprising two barriers 114, 601. Barrier 601 is added to enable the system to withstand forces and pressure according to arrow 604. As illustrated in FIG. 6, barrier 601 is held in place by holding sleeve 603 and wedge 602. Further to this embodiment, barrier 601 is removed as a consequence of removing or disintegrating barrier 114. When barrier 114 is disintegrated as shown in FIG. 5 c, barrier 601 will be exposed to the disintegrated barrier 114 and to fluid forces acting on barrier 601 from a direction indicated by arrow 210, where barrier 601 has a very limited pressure integrity.

In another embodiment of the invention, barrier 601 may be activated by a similar activation system and method as described in relation to FIGS. 2-5. Such an activation mechanism could be independent to or form integral part of activation system 113.

In one embodiment of the present invention, the lower of the two barriers, i.e. barrier 601 is the one that is operated by the activation system 113 as discussed above. This means that the barrier system disclosed in FIG. 6 is turned upside down. In many cases it is desirable to open the well in an underbalanced state, meaning that the volume above the upper barrier 114 has been filled with a relatively light fluid, such as brine, on that the reservoir is able to produce fluids into the well immediately upon barrier removal. By means, “shock-injecting” potentially polluted fluid into the formation is avoided, and a potential cleaning effect by “shock producing” from the reservoir into the well when removing the barrier is achieved. Thus, to enable barrier removal at underbalance, the lower barrier 601 must be removed prior to removing the upper barrier 114.

In even another embodiment of the invention, barriers 114 and 601 are operated simultaneously when activating the activation system 113.

In one embodiment of the present invention barriers 114 and 601 are fully or partially merged into one structural element with a cavity inside of it.

In all embodiments exemplified in FIGS. 2-6, the barriers such as barrier 114 are prevented from disintegrating in the reverse direction from what is illustrated in FIG. 5 by mechanical forces applied by such as finger coupling 207, holding sleeve 208 and elastomeric membrane 212. Also, in a preferred embodiment of the invention, barriers such as barrier 114 are further held in place by the aid of pressure forces acting on them via the elastomeric membranes such as elastomeric membrane 212. Further to FIG. 6, this is achieved by always ensuring that there is a lower pressure between the barriers 114, 601 than there is on the top of barrier 114 and bottom of barrier 601, respectively. In one embodiment, this is achieved by having atmospheric pressure conditions in the area between the barriers 104, 601. By means, well pressure from above barrier 114 and below barrier 601 will keep the barriers in place until the activation system 113 is activated.

In one embodiment, vacuum is applied to the cavity between barrier 114 and 601, to ensure that pressure forces keep the barriers in place and intact while handling them on the surface, with atmospheric pressure in the surroundings.

In one embodiment, the activation system 113 does not comprise the finger coupling 207 and associated mechanisms. Instead, the barriers 114 and 601 are removed by leading high pressure into the cavity there between, either sourced from a location above barrier 114 or below barrier 601, or on the radial outside of thereof or from a pressurized fluid reservoir that forms part of the installed downhole assembly. One such activation system is known from the publication WO 2009126049.

In one embodiment, disintegration of the barrier according to the present invention is achieved by leading high pressure fluid into the cavity between the barriers 114, 601 as shown, in combination with removal of mechanical support of one or more barrier.

In one embodiment, the elastomeric membrane 212 will hold the barrier 114 mechanically stable by means of mechanical forces/mechanical rigidity associated with membrane 212 (similar considerations applying for barrier 601).

In one embodiment, the cycle open system 112 and/or activation system 113 are incorporated in one or all of the barriers 114, 601, and/or smaller barrier elements 114 a, 114 b, 114 k.

In the following figures, for simplicity, the inner parts of the cut activation system are not shown.

Now consider FIG. 7. Further to the illustrations herein, in one embodiment of the invention, the barriers 114, 601 described in FIG. 6 are supplemented with additional barriers 114′, 601′. This may be required in cases where added safety and/or redundancy are needed.

FIG. 8 a illustrates an embodiment where the barriers 114, 601 are provided with rod elements 801, 802 that will apply push to the keystones 114 k, 804 when one or both of the barriers 114, 601 are activated. In other embodiments of the invention, the rods 801, 802 are replaced by cutting elements that will be forced up between, inside or through the barriers 114, 601 and through the elastomeric membranes such as elastomeric membrane 212. The intention with the design shown in FIG. 8 is to prevent accidental occurrences where the barriers 114, 601 re-form stable barrier constructions after activation rather than to disintegrate.

In a preferred embodiment, should the main (cycle open) barrier removal/disintegration method fail to operate, a cutting device will be deployed on wireline or coil tubing and applied to cut through the membrane 212. By means, this will entail that the upper barrier 114 will leak, and this will cause pressure to act on top of barrier 601 so that this disintegrates (as it is not designed to hold pressure from that direction). By subsequently bleeding off pressure above barrier 114, this will disintegrate, too, for similar reasons, as the higher reservoir pressure will act on it in the reverse direction. In some embodiments, the membrane 212 is mechanically protected or double barriers are applied (as described in relation to FIG. 7). This could be the case if the operational sequence of completing the well involves risks of objects accidentally falling down on the membrane 212 and causing this to leak when it was supposed to provide pressure integrity. In such cases, further to another embodiment of the invention, a spear device will be deployed on wireline or coil tubing and applied to crush the barrier 114. In one embodiment the wireline tool will be a combined cutting and spear device.

Now consider FIG. 5 b. For simplicity, only one barrier 114 is shown. In this embodiment, the finger coupling 207 is different in form and function from what has been described above. In FIG. 8 b two different profiles are supporting the barrier 114. The supporting profiles are lower support shoulder 805 and upper support shoulder 806. In the embodiment shown, the lower support shoulder 805 is part of the finger coupling 207, and can be operated in a radial or longitudinal direction as illustrated by arrows 807 and 808. In the same embodiment, the upper support shoulder 806 forms part of or is fixed to the tubing 106. Thus, when the lower support shoulder 805 is released, pressure forces further to arrow 210 will attempt to force the barrier 114 downwards. The upper support shoulder 806 will oppose this, but further to a preferred embodiment, this shoulder is made so thin that the local compression forces on the barrier 114 where this is in contact with upper support shoulder 806 will cause the barrier 114 to deform or partly disintegrate along this surface. Upon this, the barrier 114 will be forced through upper support shoulder 806. In a preferred embodiment, this sequence of events will cause the barrier 114 to open in a fashion where the lower, now unsupported outskirts of the barrier 114 will be forced towards the tubing wall, and barrier 114 opens similarly to “a flower that is blooming”. The intention with the features described above and indicated in FIG. 8 b is to provide for as controlled a disintegration of barrier 114 as possible, and to avoid an accidental situation where the barrier 114 looses support, but does not disintegrate, and where it lands on a lower-lying shoulder (not shown) in the well and re-establishes as a stable structure.

FIG. 8 c illustrates the process of opening the barrier like a blooming flower in more detail. Here, the lower support shoulder 805 shown in FIG. 8 b has been removed, and the barrier 114 now only rests on the upper support shoulder 806. The loss of radial support combined with the force (indicated by arrow 210) acting on the barrier, causes the barrier elements 114 a, 114 b, 114 c to be forced outwards towards the tubing wall, as illustrated by arrows 809 a and 809 b. The outward movement can be a result of physical displacement of the barrier elements 114 a, 114 b, 114 c, 114 k as well as deformation and physical destruction from exposure to the fluid force 210. In the embodiment shown, the barrier elements 114 a, 114 b, 114 c will be forced outwards to such a degree that the “key stone” element 114 k of the barrier elements can pass through the center of the barrier 114, as illustrated by arrow 810, whereupon the entire barrier structure will collapse.

In one embodiment, both the upper support shoulder 806 and lower support shoulder 805 are operable. For example, both shoulders 806, 805 could be operable in a longitudinal direction of the well as indicated by arrow 808. For this embodiment, it is preferred that the upper support shoulder 806 has a longer permitted distance of movement than the lower support shoulder 806, so that the support shoulders does not re-establish in a fully supporting modus with respect to barrier 114. For this embodiment, as the lower support shoulder 805 is permitted to travel a certain longitudinal distance before landing on a dedicated stop profile, a shock force will be applied on the barrier 114 in addition to the static fluid pressure forces. In one embodiment, such shock force will help deforming and/or partly disintegrating the barrier 114 in the area where this is in contact with lower support shoulder 805.

In the embodiment shown in FIG. 9, an associated system component is introduced in the form of a pressure compensation system 901. To facilitate the illustration of the pressure compensation system 901, the right side of the cut tubing is shown in a larger scale with respect to the barrier and pipe dimension. A main intention with a pressure compensation system is to balance pressure in the cavity 902 between barriers 114, 601 (the second portion of the wellbore) with respect to the pressure on the outside of the barriers 114, 601 (the first portion of the wellbore). That way, the barriers 114, 601 may not be required to withstand as large forces as would be the case if there was atmospheric pressure inside cavity 902. This may entail the barriers 114, 601 to be built more slender. In some cases, the inclusion of pressure compensation 901 will enable use of the barrier in cases where it would not be physically possible to apply a similar barrier system with atmospheric pressure inside cavity 902. The illustrated pressure compensation system 901 balances the cavity 902 pressure with respect to tubing pressure above the barrier 114. In an alternative embodiment (not shown), the pressure compensation system 901 balances the pressure with respect to tubing pressure below barrier 601, or from the annulus between the tubing and the casing of the well. The pressure compensation system 901 is in fluid communication with the inside of the tubing via channel 903 and in fluid communication with the cavity 902 via channel 904. Channel 903 is in fluid contact with piston 905 which is supported by spring 906. By means, as the completion is run in the hole, the increased tubing pressure will act on piston 905 via channel 903, whereupon the piston 905 will travel downwards and pressurize the fluid of cavity 902 via channel 904. However, due to the spring 906 exerting force on the low side of the piston 905, the pressure inside cavity 902 will always be lower than the pressure inside the tubing, acting on channel 903.

In one embodiment of the invention, the cavity 902 is filled with a vacuumed fluid, which may for example be inserted in combination with a small gas pocket. The gas pocket is intended to compensate for temperature derived fluid expansion inside cavity 902 as the system is lowered into the hot well climate. Such temperature expansion could, if not compensated for, cause barriers 114, 601 to leak and malfunction. In another embodiment, said temperature expansion is compensated for by allowing for a compensating travel of piston 905.

In one embodiment of the invention, the system is prepared for installation in the well by pushing the piston 905 to a position where the spring 906 is compressed whilst filling cavity 902 with said fluid and/or fluid/gas mixture. After filling the cavity 902 and closing the fill port (not shown in the drawing), piston 905 is released so that the spring 906 pushes it upwards. By means, a pressure that is lower than the surrounding (atmospheric) pressure is created inside the cavity 902. This may assist keeping the barrier elements 114,601 more stable during assembly and intervention into the well, as the elastomeric membrane will be subject to suction forces from the inside of the barrier.

Now consider FIG. 10. In many cases, during the installation sequence of the well completion, the pressure on top of barrier 114 and barrier 601, respectively, may vary with respect to each other. For example, the completion equipment may be run in drilling mud, hence barrier 114 as well as barrier 601 may be exposed to pressures equal to the hydrostatic column of drilling mud when installed at depth. In the tubing above barrier 114, the mud may be displaced with so-called completion fluids, normally salt water, prior to setting the production packer and opening the barrier. As the completion fluid normally is less dense than the drilling mud, the pressure on top of barrier 114 may now become significantly lower than the pressure below barrier 601. In other circumstances, other parameters may change this relation. In all cases, it is important that the pressure inside cavity 902, which is the second portion of the wellbore as stated in the first aspect of the invention, always is lower than the pressure in the first portion of the wellbore, i.e. the pressure above barrier 114 and below barrier 601 as shown in the figures, during all relevant stages of the well completion process. Should the cavity 902 pressure exceed any of those pressures at any stage, this may entail leaks, and in worst case a premature disintegration of the barriers 114, 601. To prevent the cavity 902 pressure from exceeding a defined maximum pressure, the piston 905 is provided with a stop rod 1001. After a certain travel of piston 905, the stop rod 1001 will abut against the bottom of the drilled bore 1002 and prevent the piston 905 from travelling further. Hence, the pressure inside cavity 905 will not increase as a function of deploying the barrier further into the well. This is illustrated in FIG. 11.

FIG. 12 illustrates a different approach to avoid over-pressurizing cavity 902. Here, channel 903 is in fluid communication with the top of piston 905 via channel 1202 in plug 1201. Plug 1201 is provided with elastomeric seals in both ends. In the initial position, plug 1201 is attached to the tubing wall by means of shear pins 1203. The cavity 1204 formed by the right end of plug 1201 and the associated bore in the tubing, and sealed off by the right end seal of plug 1201, is initially housing a gas at near atmospheric pressure. As the barrier is lowered into the well and the surrounding pressure increases, the shear pins 1203 will shear at a certain depth, hence pressure due to forces generated by the pressure differential between cavity 1204 and the surrounding pressure. This is illustrated in FIG. 13 and will cause the plug 1201 to move to the right. When fully shifted, the left side seal of plug 1201 will be in contact with the wall of channel 903 and form a seal. Hence, further pressure increases inside cavity 902 as a function of lowering the barrier into the well will not take place.

FIG. 14 illustrates an embodiment where the piston and plug mechanism is mirrored above and below barriers 114 and 601, to compensate from both top and bottom of the barrier. The capacity of the shear pins 1203 in the upper piston and plug mechanism as shown in FIG. 13 may be equal to or different from the capacity of the shear pins for the mirrored piston and plug mechanism arranged below the barrier 601. The capacity may be selected depending on the given case specifications.

FIG. 15 illustrates one method for defining the barrier elements of the barrier 114, some of which are indicated by reference numerals 114 a, 114 b, 114 c, 114 k. In the embodiment shown in FIG. 15 cuts are made in the concave lens shape of the barrier 114 from an imaginary point 1501 located somewhere on the center line axis 115 pointing straight out of the center of the barrier 114, i.e. the center axis 115 of the wellbore or tubular element (not shown) wherein the barrier 114 is mounted.

In the embodiment shown, the lens-shaped barrier 114 is provided with cuts running from the point 1501, the cuts being symmetrical with respect to the center line axis 115 of the wellbore/tubular. In one embodiment, two sets of cuts such as the illustrated cuts are made perpendicular (or in any desired angle) to each other with respect to the xy plane. As a result, the smaller elements 114 a, 114 b will assume a wedge shaped form with a cubic base along the outskirts of barrier 114, whereas the form will be a concave cubic/rectangular shape in the center of the lens.

In a preferred embodiment, the smaller elements 114 a, 114 b, 114 c, 114 k are made by providing circular cuts that are concentric with the circumference of the barrier 114, the cuts being made along lines that resemble the lines running out of point 1501. Subsequently, radial cuts are made from the outskirts of the barrier 114 towards the centre. In one embodiment, the entire barrier is cut by the said radial cuts all the way from the outskirts to centre. In another embodiment, the centre barrier element 114 k, the “key stone”, is not cut. Hence, the barrier elements 114 a, 114 b, 114 c will be formed from concentric and radial cut intersections, with the exception of the key stone barrier element 114 k that will have a substantially frustoconical shape wherein the surface area facing the first portion of the wellbore is larger than the surface area facing the second portion of the wellbore. This is clearly shown in FIGS. 16 a-16 c that will be discussed below.

The barrier elements 114 a, 114 b, 114 c, 114 k will in the embodiment shown resemble building blocks of an igloo; however the blocks along the circumference of the “lens” will be supported by an angled base rather than a horizontal base.

In one embodiment, the barrier 114 will be constituted by barrier elements 114 a, 114 b, 114 c, 114 k defined by cuts that run all the way from the top/outer end to the bottom/inner end of the barrier. In another embodiment, layered sub elements (not shown) that are constituted by smaller barrier elements 114 a, 114 b, 114 c, possibly with thin walled dome elements (similar to the dome element 114 s shown for example in FIG. 2) in between and/or on the outskirts of the layer barrier elements, form the complete assembled barrier 114.

In a preferred embodiment the smaller elements 114 a, 114 b are molded elements, made of fibre armed concrete or other rugged materials suitable for molding, able to withstand the required forces. In another embodiment, the smaller elements 114 a, 114 b, 114 c, 114 k are machined or manufactured in alternative known fashions. Preferably, the barrier elements are made of a material having a higher density than that of the fluid in the wellbore. This to ensure that the disintegrated barrier elements sink down in the well and do not represent any risk for malfunction of e.g. any valves arranged downstream of the sealing arrangement 108 arranged in a producing well. However, the barrier elements may also be made of a material having a lower density than that of the fluid in the wellbore, if it is desired to prevent the disintegrated barrier elements to sinking in the well.

FIG. 16 a-c illustrates further details of a design of the force bearing part of barrier 114 according to one embodiment of the present invention. FIG. 16 a shows an exploded isometric view, FIG. 16 b shows and isometric view of an assembled barrier 114 shown in FIG. 16 a and FIG. 16 c shows a top view of the assembled barrier 114. Further to this embodiment, the barrier 114 is made up of rings 1601-1604 cut in a concentric fashion, with an angle on the outskirts further to the logic as explained with respect to FIG. 15. The rings 1601-1604 are radially cut in barrier elements 114 a, 114 b, 114 c, 114 k. In the embodiment shown, the barrier elements in one ring are mounted with an angular displacement with respect to the barrier elements in adjoining ring(s). This way, for the embodiment shown, the splice between two barrier elements of ring 1601 meets the center of a barrier element in ring 1602 etc. This way, the barrier 114 becomes more physically stable. 

1. A well barrier for sealing off a first portion of a wellbore from a second portion of the wellbore, the first portion having a higher fluid pressure than the second portion, wherein the well barrier is held in place in the wellbore by a holding means preventing movement of the well barrier in a direction from the first portion to the second portion, the well barrier comprising: multiple barrier elements initially held together by a connection means to form the barrier, the barrier having a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore; a sealing means for preventing fluid flow from the first portion to the second portion; and a destabilizing mechanism arranged for disengaging the connection means from at least one of the barrier elements upon activation of the mechanism, so that support between adjoining barrier elements is removed thereby disintegrating the well barrier.
 2. The well barrier of claim 1, wherein the multiple barrier elements are formed in one piece provided with notches in at least a portion of the surface of the well barrier, and the connection means comprises the non-notched portion of the well barrier.
 3. The well barrier of claim 1, wherein the barrier elements are provided by means of separate, preshaped barrier elements being connected to each other by the connection means, the connection means being selected from one of or a combination of: an adhesive; a wire; the sealing means, to form the well barrier.
 4. The well barrier of claim 1, wherein the well barrier is further provided with a support element for supporting the barrier elements, the support element facing the second portion of the wellbore.
 5. The well barrier of claim 1, wherein the sealing means is a sealing element facing the first portion of the wellbore.
 6. The well barrier of claim 5, wherein the sealing element is selected from the group consisting of an elastomeric membrane, a coating, and an adhesive.
 7. The well barrier of claim 1, wherein the sealing means is the non-notched portion of the well barrier.
 8. The well barrier of claim 1, wherein the well barrier is provided with a pressure arch towards the first portion of the wellbore.
 9. The well barrier of claim 1, wherein the well barrier is provided with a further well barrier, the further well barrier being mirrored with respect to the well barrier about a plane being perpendicular to a longitudinal axis of the wellbore.
 10. The well barrier of claim 9, wherein the second portion of the wellbore is defined between the well barrier and the further well barrier.
 11. The well barrier of claim 1, wherein the destabilizing mechanism comprises a releasable holding means arranged such that upon releasing the holding means the well barrier is moved by the fluid in the first portion, the movement causing the well barrier to disintegrate.
 12. The well barrier of claim 1, wherein the destabilizing mechanism is an arrangement for raising the pressure of the fluid in the second portion to a level higher than the fluid pressure in the first portion of the wellbore facing the further well barrier.
 13. The well barrier of claim 1, wherein at least one of the multiple barrier elements has a form as a keystone supporting adjoining barrier elements, the keystone element having a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore.
 14. The well barrier of claim 13, wherein the at least one keystone element is provided by means of multiple elements.
 15. The well barrier of claim 1, wherein the barrier facing the first portion of the wellbore has a concave lens shape, and wherein a majority of the barrier elements are wedge shaped with a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore.
 16. A method for controlling a disintegration of a well barrier for sealing off a first portion of a wellbore from a second portion of the wellbore, the first portion having a higher fluid pressure than the second portion, wherein the well barrier is held in place in the wellbore by a holding means prevention movement of the well barrier in a direction from the first portion to the second portion, the well barrier comprising: multiple barrier elements initially held together by a connection means to form the barrier, the barrier having a surface area facing the first portion of the wellbore that is larger than the surface area facing the second portion of the wellbore; a sealing means for preventing fluid flow from the first portion to the second portion; and a destabilizing mechanism arranged for disengaging the connection means from at least one of the barrier elements upon activation of the mechanism, so that support between adjoining barrier elements is removed, thereby disintegrating the well barrier, the method comprising: pre-shaping the barrier to disintegrate in multiple barrier elements of desired size and shape; and activating a destabilizing mechanism that will provide a force sufficient to break a connection means initially holding the multiple barrier elements together, thereby causing the barrier to disintegrate into said multiple barrier elements of desired size and shape. 